Some examples of bis-quaternary or polycationic quaternary ammonium compounds imparting useful rheological properties to aqueous solutions have been studied and reported. For example, U.S. Pat. No. 4,734,277, to Login, issued on Mar. 29, 1988, in general, describes the preparation of certain bis-quaternary compounds by reacting tertiary amines with a suitable epoxide, such as epichlorohydrin, and further describes that the resulting bis-quaternary ammonium compounds have utility as an additive in cosmetics applications, such as hair conditioners, skin lotions, etc.
Additionally, U.S. Pub. Pat. Appl. 2004/0067855, to Hughes, et al., published on Apr. 8, 2004, describes certain bis-quaternary or oligomeric cationic quaternary ammonium compounds useful in a viscoelastic wellbore treatment fluid for controlling the viscoelasticity of that fluid.
Hydrocarbons such as oil, natural gas, etc., are obtained from a subterranean geologic formation by drilling a well that penetrates the hydrocarbon-bearing formation. This drilling outcome provides a partial flow path for the hydrocarbon, typically oil, to reach the surface. In order for oil to travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flow path through the rock formation (e.g., sandstone, carbonates), which generally occurs when rock pores of sufficient size and number are present.
A common impediment to oil production is “damage” to the formation, which plugs the rock pores and impedes the flow of oil. Moreover, depletion of zones nearest to the wellbore causes a gradual decline in production. Generally, techniques used to increase the permeability of the formation and to provide extended conduits to the wellbore are referred to as “stimulation.” Aqueous gels are often used in different well stimulation processes.
For example, in a fracturing process, which is one kind of well stimulation technique, cracks or fissures (fractures) are created in subterranean formations. Gels are used in fracturing processes as the medium which transfers energy from outside the subterranean formation to the specific locations inside the subterranean formation in order to create the desired fractures. The energy to create the fractures is transferred primarily as pressure against the formation, by pumping the fracturing fluid into the wellbore where it is directed to desired portions of the subterranean formation. The gels are relatively incompressible fluids, and pressure is exerted against the subterranean formation until the force is sufficient to fracture the formation. Once the fracture is created, the high viscosity gel flows into the newly formed cracks and fissures. As the fracturing fluid flows into the fracture, it carries proppant (e.g., small particles of sand, ceramics, or other hard material) into the fracture. Once the force from pumping the fracturing fluid is removed, the proppant remains in the fractures, which prevents the fractures from closing. The fracturing fluid is then removed from the wellbore, and the wellbore is prepared for recovering further amounts of hydrocarbon(s).
Older technology utilizes polysaccharide polymers to form the aqueous gels utilized as fracturing fluids. Often, the polysaccharide gels are cross-linked using additives such as titanates, zirconates or borates. Once the fracturing process is complete, these gels normally require a separate process to remove them from the wellbore, which typically requires a significant amount of time and additional well treatment chemicals. Furthermore, complete removal of the polymer gel is seldom attainable, and the polymer that remains in the wellbore can clog the pores of the rock formation, thus preventing hydrocarbon from flowing through and from the pores.
Modified polysaccharides have been studied in different fields of applications. For example, U.S. Pat. No. 4,663,159, to Union Carbide Corporation, describes water soluble quaternary ammonium polysaccharides having from 50 to 20,000 repeat units and hydrophobic substitution. Allegedly, the cationic polysaccharides of U.S. Pat. No. 4,663,159 have enhanced viscosity, foaming and preferably improved surface properties, and possess utility in personal care, emulsions and cleansers.
For another example, U.S. Pat. No. 5,384,334, to Amerchol Corporation, describes alkoxylated alkyl glucosides having quaternary nitrogen-containing ether substituents, which allegedly possess cationics utility combined with extreme mildness to skin and hair, and are allegedly suitable for stable personal care compositions and processes.
U.S. Pat. No. 5,387,675, to Rhone-Poulenc Specialty Chemicals Co., relates to modified hydrophobic cationic thickening compositions, which allegedly have multiple uses as thickeners and are particularly suited for use in personal care products and in oil recovery. It describes water soluble quaternary alkyl ammonium ethers of polysaccharides or polyols (e.g. polyvinyl alcohol, polyethylene glycol, and glycerol) wherein the degree of substitution of the ethers is from about 0.001 to about 0.5.
One problem associated with at least some the modified cationic polysaccharides of the prior art is that the glycosidic hydroxyls or alkyl glycosides in these cationic polysaccharides are chemically labile groups, subject to hydrolysis. Hydrolysis rates are especially pronounced under aqueous conditions, with the rate of hydrolysis increasing as the pH decreases. Since many of the uses for viscoelastic compositions are in aqueous conditions, and some oil field applications are in harsh acidic aqueous conditions, glycosidic groups and the cationic polysaccharides of the prior art are not stable and thus disadvantageous.
Non-polymeric gellants (NPGs) are more recent technological developments that provide alternatives to polysaccharide gels. NPGs are surfactants, and usually are quaternary ammonium compounds (cationic) or amphoteric compounds. Particularly desired NPGs are viscoelastic surfactants (VESs) that can form viscoelastic solutions because certain properties of viscoelastic prove useful for well stimulation processes. One such property is the ability of a viscoelastic solution to transport proppant at lower viscosities than a polymer solution. Another useful property is the reduction of friction between the moving fluid and the surfaces contacted therewith. An especially useful feature of viscoelastic gels is that, on contact with hydrocarbons, the gels break with a resultant sharp drop in viscosity. At the lower viscosity, removal of the fracturing fluid from the wellbore requires no additional well treatment chemicals, and requires less time and equipment than do polymeric gellants. NPG surfactant gels may also be broken by other means. Furthermore, unlike polysaccharide gellants, there is much lower tendency of the NPGs to clog the hydrocarbon-producing pores in the subterranean formation.
NPGs are also useful in other well treatment applications. For example, they can reduce the loss of fracturing fluid into subterranean formations; reduce the production of water from wells; form gels for wellbore cleaning; and reduce friction in solutions.
The application of viscoelastic surfactants in both non-foamed and foamed fluids used for fracturing subterranean formations have been described in several patents, e.g. EP 0835983 B1, to Brown et al., issued Dec. 17, 2003; U.S. Pat. No. 5,258,137, to Bonekamp et al., issued on Nov. 2, 1993; U.S. Pat. No. 5,551,516, to Norman et al., issued on Sep. 3, 1996; U.S. Pat. No. 5,964,295, to Brown et al., issued on Oct. 12, 1999; and U.S. Pat. No. 5,979,557 to Card et al., issued on Jun. 16, 1999.
The use of viscoelastic surfactants for water shut off treatments and for selective acidizing is discussed in British Patent Application No. GB 2332224 A, to Jones et al., published on Jun. 16, 1999; and Chang F. F., Love T., Affeld C. J., Blevins J. B., Thomas R. L. and Fu D. K., “Case study of a novel acid diversion technique in carbonate reservoirs”, Society of Petroleum Engineers, 56529, (1999).
More recent developments in this field can be found in U.S. Pub. Pat. App. No. 2004/0102330 A1, to Zhou, et al., published on May 27, 2004, which describes cleavable monomeric viscoelastic surfactants; and U.S. Pub. Pat. App. No. 2004/0067855 A1, to Hughes, et al., published on Apr. 8, 2004, which describes oligomeric anionic or cationic viscoelastic surfactants (including dimeric and trimeric forms).
Conventional cationic NPGs used in the hydrocarbon recovery field utilize alkyl amines with a single hydrophobic carbon chain. To be useful in fracturing applications, the hydrophobe chains of conventional cationic NPGs are preferably and predominantly 18 carbon atoms in length, and more preferably greater than 18. An example of one such commercially available material is ClearFRAC™, commercially available from Schlumberger-Doll Research (“Schlumberger,” Ridgefield, Conn.), i.e., erucyl-N,N-di-(2-hydroxyethyl)-N-methylammonium chloride (EHMAC), which is asserted to provide performance at the highest application temperatures (up to about 250° F. (about 121° C.)) of any currently commercially available viscoelastic fracturing fluid. This product reportedly contains less than 3% hydrophobe carbon chains of 18 carbons or less. Because the intermediate used to make EHMAC must be purified to remove the components with alkyl chains of 18 carbons or less, EHMAC costs substantially more to produce than other alkyl amine cationic materials. The high cost of EHMAC limits the number of stimulation processes for which it is used on a repeated basis.
A commercially available alternative to ClearFRAC™ is AquaClear™ surfactant fracturing fluid, commercially available from BJ Services Company (“BJ Services”, Houston, Tex.). It also uses a quaternary alkylamine, but is less costly because an extensively purified intermediate is not required. However, the maximum application temperature for AquaClear™ is about 170° F. (about 76.7° C.), which is substantially lower than ClearFRAC™'s 250° F. (about 121° C.).
While having some obvious advantages over polysaccharide gels, conventional NPG gels also have some disadvantages. One is the temperature limitation of conventional NPG surfactant gels. As well depth increases, wellbore hole temperature usually also increases, and may frequently exceed 250° F. (about 121° C.). Currently, conventional NPG surfactant technology fails under these conditions, while polysaccharide gels continue to perform. Another disadvantage is cost, in that the material cost for polysaccharide gels is substantially lower than that for NPG surfactant gels.
Yet another disadvantage of conventional NPG surfactants is their toxicity to the environment and their poor biodegradability. Because cationic alkylamines do not breakdown readily in the environment, they tend to accumulate. Alkylamine quaternary compounds are also toxic to many life forms, so they can have a destructive impact particularly on environments in which they accumulate. Some areas of the world have imposed regulatory restrictions on chemicals based on their being hazardous to the environment. For example, in the North Sea, chemicals such as cationic alkylamine are either restricted or banned entirely.
Still another disadvantage of conventional NPG surfactants is their poor solubility, poor salt stability, and/or poor acid solubility in highly concentrated salt solutions, such as those high density brines used in wellbore service fluids.
Thus, there is a need for gellants, in particular, viscoelastic gellants, that can provide all or most of the advantages of the conventional NPG technology, and that (1) can provide viscoelastic properties at higher temperatures (greater than 80° C. or 176° F., and preferably greater than 110° C. or 230° F.); (2) are more eco-friendly; (3) are more cost effective; (4) have increased solubility in highly concentrated salt solutions; and/or (5) can provide improved salt stability and/or acid solubility. The presently described technology addresses these needs.